Surfactants for oil and gas production

ABSTRACT

Surfactants for use in formulations and processes suitable for hydrocarbon recovery. These formulations, include formulations suitable for fracking, enhancing oil and or gas recovery, and the recovery and or production of bio- based oils.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a divisional of U.S. Application No. 17/127,033,filed Dec. 18, 2020, which claims priority to U.S. ProvisionalApplication No. 62/955,873, filed Dec. 31, 2019, the disclosures ofwhich are herein incorporated by reference in their entireties.

FIELD

The present disclosure pertains to surfactants for use in the productionand recovery hydrocarbon, including oil and gas from wells and oils frombio-based processes. Such surfactants may include siloxane derivativesof amino acids wherein the siloxane derivatives have surface-activeproperties.

BACKGROUND

Surfactants (molecules with surface-active properties) are widely usedin commercial production of oil and natural gas. These formulations mayinclude a variety of liquids, emulsions, and foams used to recoveryhydrocarbons from the earth and from bio-based sources. Both oil andnatural gas may be found in contact with water or with water solublesubstrates accordingly, surfactants may be included in formulations toimprove the recovery of oils and/or gasses. Ideally, formulations forsuch production and recovery processes are easy to manufacture, deploy,and if practical, reuse.

The surfactants may be uncharged, zwitterionic, cationic, or anionic.Although in principle any surfactant class (e.g., cationic, anionic,nonionic, amphoteric) is suitable, it is possible that a formulation mayinclude a combination of two or more surfactants from two or moresurfactant classes.

Often, surfactants are amphiphilic molecules with a relativelywater-insoluble hydrophobic “tail” group and a relatively water-solublehydrophilic “head” group. These compounds may adsorb at an interface,such as an interface between two liquids, a liquid and a gas, or aliquid and a solid. In systems comprising relatively polar andrelatively non-polar components the hydrophobic tail preferentiallyinteracts with the relatively non-polar component(s) while thehydrophilic head preferentially interacts with the relatively polarcomponent(s). In the case of an interface between water and oil, thehydrophilic head group preferentially extends into the water, while thehydrophobic tail preferentially extends into the oil. When added to awater-gas only interface, the hydrophilic head group preferentiallyextends into the water, while the hydrophobic tail preferentiallyextends into the air. The presence of the surfactant disrupts at leastsome of the intermolecular interaction between the water molecules,replacing at least some of the interactions between water molecules withgenerally weaker interactions between at least some of the watermolecules and the surfactant. This results in lowered surface tensionand can also serve to stabilize the interface.

At sufficiently high concentrations, surfactants may form aggregateswhich serve to limit the exposure of the hydrophobic tail to the polarsolvent. One such aggregate is a micelle. In a typical micelle themolecules are arranged in a sphere with the hydrophobic tails of thesurfactant(s) preferentially located inside the sphere and thehydrophilic heads of the surfactant(s) preferentially located on theoutside of the micelle where the heads preferentially interact with themore polar solvent. The effect that a given compound has on surfacetension and the concentration at which it forms micelles may serve asdefining characteristics for a surfactant.

Crude oil development and production from oil bearing formations caninclude up to three phases: primary, secondary and tertiary (orenhanced) recovery. During primary recovery, the natural energy presentin the formation (e.g., water, gas) and/or gravity drives oil into theproduction wellbore. As oil is produced from an oil bearing formation,pressures and/or temperatures within the formation may decline.Artificial lift techniques (such as pumps) may be used to bring the oilto the surface. Only about 10 percent of a reservoir’s Original Oil InPlace (OOIP) is typically produced during primary recovery. Secondaryrecovery techniques are employed to extend the field’s productive lifeand generally include injecting a displacing fluid such as water(waterflooding) to displace oil and drive it to a production wellbore.

Secondary recovery techniques typically result in the recovery of anadditional 20 to 40 percent of a reservoir’s OOIP. However, even ifwaterflooding were continued indefinitely, typically more than half ofthe OOIP would remain unrecovered. Poor mixing efficiency between waterand oil (because of high interfacial tension between the water and oil),capillary forces in the formation, the temperature of the formation, thesalinity of the water in the formation, the composition of the oil inthe formation, poor sweep of the injected water through the formation,and other factors contribute to the inefficiency. Primary and secondarytechniques therefore leave a significant amount of oil in the reservoir.

With much of the easy-to-produce oil already recovered from oil fields,producers have employed tertiary, or enhanced oil recovery (EOR),techniques that offer potential for recovering 30 to 60 percent or moreof a reservoir’s OOIP. Three major categories of EOR have succeededcommercially: thermal recovery, gas injection, and chemical techniques.Thermal recovery introduces heat (e.g., injection of steam) to lower theviscosity of the crude oil to improve its ability to flow through thereservoir. Gas injection uses nitrogen, carbon dioxide, or other gasesthat expand in a reservoir to push additional oil to a productionwellbore. Other gases dissolve in the oil to lower its viscosity andimprove its flowability. Chemical techniques inject surfactants(surfactant flooding) to reduce the interfacial tension that prevents orinhibits oil droplets from moving through a reservoir or inject polymersthat allow the oil present in the formation to more easily mobilizethrough the formation.

Chemical techniques can be used before, during, or after implementingprimary and/or secondary recovery techniques. Chemical techniques canalso complement other EOR techniques. Surfactant flooding may includesurfactant polymer (SP) flooding and Alkali Surfactant Polymer (ASP)flooding. In SP flooding, a reservoir is injected with water and/orbrine containing ~1 wt.% surfactant and -0.1 wt.% polymer. ASP floodingincludes alkali in addition to the components used in SP flooding. ASPsystems typically contain ~0.5 to 1 wt.% alkali, -0.1 to 1 wt.%surfactant, and ~0.1 to 1 wt.% polymer. Typically, an SP or ASP flood isfollowed up with an injection of a displacing fluid, e.g., a waterfloodand/or polymer “push fluid. The choice between SP or ASP depends on theacid value of the oil to be recovered, the concentration of divalentcations in the reservoir’s brine, the economics of the project, theability to perform water softening or desalination, and other factors.Alkali sequesters divalent cations in the formation brine and therebyreduces the adsorption of the surfactant during displacement through theformation. Alkali also generates an anionic surfactant (sodiumnaphthenate soap) in situ in the formation by reacting with naphthenicacids that are naturally present in the crude oil. The use of relativelyinexpensive alkali reduces the surfactant retention and hence reducesthe amount of surfactant required, and therefore also reduces theoverall cost. Alkali can also help alter formation wettability to a morewater-wet state to improve the imbibition rate.

In “wettability alteration,” another EOR technique, surfactants areintroduced into a reservoir, sometimes combined with alteringelectrolyte concentration, to displace adsorbed oil by effectingspontaneous imbibition of water onto the reservoir rock. This techniquedoes not necessarily require low interfacial tensions between the oiland aqueous phases or the formation of a microemulsion phase. It alsodoes not require a good sweep efficiency of the displacing fluid, and assuch could have utility in carbonate reservoirs which can be fracturedand typically have poor conformance. Surfactants used in SP and ASPfloods have also displayed utility in wettability alteration.

A surfactant system, after injection into an oil bearing formation,takes up crude oil and brine from the formation to form a multiphasemicroemulsion in situ. When complete, the microemulsion is immisciblewith the reservoir crude and exhibits low interfacial tension (IFT) withthe crude oil and brine. Commercial surfactant EOR processes achieveultralow IFTs (i.e., less than 10 mN/m) to mobilize disconnected crudeoil droplets in the formation and create an oil bank where both oil andwater flow as continuous phases. IFT changes with salinity, surfactantcomposition, crude oil com position, formation temperature, and othervariables. For anionic surfactants, an optimal salinity exists at whichthe microemulsion solubilizes equal Volumes of oil and water, and atwhich the microemulsion exhibits nearly equal IFTs with oil and brine.The ultra-low IFT generally exists only in a narrow salinity range thatoverlaps the optimal salinity for a given microemulsion.

As explained by P. Zhao et al. (“Development of High-PerformanceSurfactants for Difficult Oils.” SPE/DOE Improved Oil RecoverySymposium, Tulsa, Okla., April 2008, SPE 113432), the “selection ofsurfactants for enhanced oil recovery applications requires laboratorytesting with crude oil from the target reservoir and may involveconsiderable effort to find a suitable surfactant and other...components ... such as polymer, electrolytes, co-surfactant andco-solvent.”

In the dry-mill ethanol process, yellow dent corn is milled, liquefiedand sent to a fermenter. Enzymes and yeast are added to convert starchinto ethanol, which is subsequently distilled off. This leaves a slurrycalled whole stillage. Whole stillage, which includes, a concentratedoil fraction, is then separated via centrifugation into liquid and solidfractions called thin stillage and wet cake respectively. While part ofthe thin stillage is recycled to help liquefy the milled corn, the restis concentrated via evaporation into thick stillage (or syrup), which isdried and mixed with the wet cake to form distillers’ dried gains withsolubles (DDGS). This is sold as cattle feed and is a good source ofprotein.

Due to the concentrating effect dry-milling has on the oil fraction,corn oil extracted from thick stillage has become a profitableco-product for the ethanol industry. Although removing corn oil lowersthe energy density of DDGS, some studies suggest that high oil contentin DDGS interferes with milk production in dairy cattle and leads toundesirable pork bellies in swine. Therefore, removing some of the oilnot only leads to a valuable co-product, but also may improve DDGSquality.

Current methods of extracting corn oil from thick stillage includesolvent extraction (often hexane) and decantation. Hexane extraction,though effective, is energy intensive and requires a large amount ofcapital investment. Decantation requires little capital investment andhas the potential of being just as effective as hexane extraction.

Decantation, using centrifuges takes advantage of the density differencebetween the oil and the aqueous phase to create buoyant force on the oilsuspended in solution. In order for the buoyant force to be strongenough to overcome the interfacial interactions and surface frictionacting on the oil, individual oil droplets must be large enough so thatsufficient force can be generated. The current separation devices usedin industry can separate particles as small as twenty micrometers indiameter. The success of current corn oil decantation is highlydependent on upstream processing conditions. Processes using hightemperate, high or low pH, smaller grinds and long periods of retentiontend to exhibit increased oil yields. These harsh conditions may not bethe preferred way to extract oils for human or animal consumptions assuch condition may adversely affect the nutritional and organolepticproperties of the final product.

The present disclosure provides formulations useful for extracting oiland natural gas from wells and in some applications from mixtures of oilbased fuels and aqueous medium used in bio based process to producehydrocarbon fuels such as biodiesel. These products may be formulated toinclude one or more surfactants from one or more surfactant classesdisclosed herein. The surfactants may be used as emulsifiers, wettingagents, dispersants, and/or agents to improve the recovery ofhydrocarbons and or the separation of hydrocarbons from environmentsthat include water.

The present disclosure provides surfactants for use in the production ofoil and gas in the form of siloxane derivatives of amino acids that havesurface-active properties. The amino acids may be naturally occurring orsynthetic amino acids, or they may be obtained via ring-openingreactions of molecules such as lactams, for instance caprolactam. Theamino acids may be functionalized with different types of siloxanegroups to form compounds with surface-active properties.Characteristically, these compounds may have low critical micelleconcentrations (CMC) and/or the ability to reduce the surface tension ofa liquid.

The present disclosure provides a fracking fluid formulation, comprisingat least one surfactant of Formula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; an optional counterion associated with thecompound which, if present, is selected from the group consisting ofchloride, bromide, and iodide; a polymer or a viscoelastic surfactant.

The present disclosure further provides a fluid for Improved OilRecovery, comprising at least one surfactant of Formula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; an optional counterion associated with thecompound which, if present, is selected from the group consisting ofchloride, bromide, and iodide; a linear, crosslinked, and/or blockcopolymer; and/or an optional viscoelastic surfactant; and an optionalco-surfactant.

The present disclosure also provides a formulation for recovering abiologically produced oil, comprising at least one surfactant of FormulaI,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; an optional counterion associated with thecompound which, if present, is selected from the group consisting ofchloride, bromide, and iodide; and water.

The present disclosure further provides a formulation for use in amixture of fracking fluid and oil or natural gas comprising at least onesurfactant of Formula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; an optional counterion associated with thecompound which, if present, is selected from the group consisting ofchloride, bromide, and iodide; and water, and optionally a gas.

The above mentioned and other features of the disclosure, and the mannerof attaining them, will become more apparent and will be betterunderstood by reference to the following description of embodimentstaken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a plot of surface tension versus concentration forSurfactant 2, with a chloride counterion measured at pH = 7 as describedin Example 1b.

FIG. 2 shows a plot of surface tension versus concentration forSurfactant 3 as described in Example 2b.

FIG. 3 shows a plot of dynamic surface tension as change in surfacetension versus time for Surfactant 3 as described in Example 2b.

FIG. 4 shows a plot of surface tension versus concentration forSurfactant 4 as described in Example 3b.

FIG. 5 shows a plot of dynamic surface tension as change in surfacetension versus time for Surfactant 4 as described in Example 3b.

FIG. 6 shows a plot of surface tension versus concentration forSurfactant 5 as described in Example 4b.

FIG. 7 shows a plot of dynamic surface tension as change in surfacetension versus time for Surfactant 5 as described in Example 4b.

DETAILED DESCRIPTION

As used herein, the phrase “within any range using these endpoints”literally means that any range may be selected from any two of thevalues listed prior to such phrase regardless of whether the values arein the lower part of the listing or in the higher part of the listing.For example, a pair of values may be selected from two lower values, twohigher values, or a lower value and a higher value.

As used herein, the word “alkyl” means any saturated carbon chain, whichmay be a straight or branched chain.

As used herein, the phrase “surface-active” means that the associatedcompound is able to lower the surface tension of the medium in which itis at least partially dissolved, and/or the interfacial tension withother phases, and, accordingly, may be at least partially adsorbed atthe liquid/vapor and/or other interfaces. The term “surfactant” may beapplied to such a compound.

With respect to the terminology of inexactitude, the terms “about” and“approximately” may be used, interchangeably, to refer to a measurementthat includes the stated measurement and that also includes anymeasurements that are reasonably close to the stated measurement.Measurements that are reasonably close to the stated measurement deviatefrom the stated measurement by a reasonably small amount as understoodand readily ascertained by individuals having ordinary skill in therelevant arts. Such deviations may be attributable to measurement erroror minor adjustments made to optimize performance, for example. In theevent it is determined that individuals having ordinary skill in therelevant arts would not readily ascertain values for such reasonablysmall differences, the terms “about” and “approximately” can beunderstood to mean plus or minus 10% of the stated value.

The present disclosure provides formulations for use in the productionand/or recovery of hydrocarbons. Such formulations include: frackingfluids; improved Oil Recovery (IOR) injection fluids; formulation forincreasing the production of natural gas; formulations for the recoverybio-oils from sources such a stillage; and vegetables, fruits, and nuts.

I. Fracking Fluids

To recover hydrocarbons from hydrocarbon-bearing subterranean geologicformations a wellbore is drilled into the formation to provide a flowpath for the hydrocarbons from a reservoir within the formation to thesurface. However, often a stimulation technique referred to as hydraulicfracturing is needed to improve the flow path and recovery of thehydrocarbon from oil or gas wells.

In hydraulic fracturing a specialized fluid is pumped into the targetedformation at a rate in excess of what can be dissipated through thenatural permeability of the formation rock. The specialized fluids usedin the technique are referred to fracturing fluids. The fluids result ina pressure build up until such pressure exceeds the strength of theformation rock. When this occurs, the formation rock fails and aso-called “fracture” is initiated. With continued pumping, the fracturegrows in length, width and height. The fracture, which is generated bythe application of this stimulation technique, creates a conductive pathto the wellbore for the hydrocarbon.

Ideally, fracturing fluids should impart a minimal pressure drop in thepipe within the wellbore during placement and have an adequate viscosityto carry proppant material that prevents the fracture from closing.Moreover, the fracturing fluids should have a minimal leak-off rate toavoid fluid migration into the formation rocks so that, notably, thefracture can be created and propagated and should degrade so as not toleave residual material that may prevent accurate hydrocarbons to flowinto the wellbore.

Some fracturing fluids comprise: (a) an aqueous medium, and (b) athickening amount of a thickener composition comprising (i) awater-soluble or water-dispersible interpolymer having pendanthydrophobic groups chemically bonded thereto, (ii) a nonionic surfactanthaving a hydrophobic group(s) that is capable of associating with thehydrophobic groups on said organic polymer, and (iii) a water-solubleelectrolyte. Additionally, the fluids preferably contain a stabilizingamount of a thiosulfate salt. As an example, an interpolymer ofacrylamide and dodecyl acrylate was used in combination with a nonionicsurfactant (HLB of from 10 to 14) to thicken a dilute aqueous solutionof KCl and sodium thiosulfate; the aqueous Solution had excellentproperties for use as a high temperature hydraulic fracturing fluid. Seefor example, Published PCT application WO 87/01758 entitled “HydraulicFracturing Process and Compositions.”

Some fracturing fluids comprise: an aqueous liquid medium havingincreased low shear viscosity as provided by dispersing into the aqueousmedium (1) a water-soluble polymer having pendant hydrophobic groups,e.g., an acrylamide dodecyl acrylate copolymer, and (2) awater-dispersible surfactant, e.g., sodium oleate, or dodecylpolyethyleneoxy glycol monoether. See, for example, U.S. Pat. No.4,432,881 entitled “Water-Dispersible Hydrophobic Thickening Agent”. Atleast some of the inventive surfactant recited herein may be included inthese formulations.

Many fracking fluids comprise: water, a thickener, polymeric gels andsurfactants. Alternative fracking fluids may include, viscoelasticsurfactants in place of polymeric gels.

1. Polymeric Gels

Polymeric gels may be comprised of one or more of the following: linearpolymers, crosslinked polymers, and/or co-block polymers.

Useful linear polymers include, but are not limited to; guar,derivatives of guar, hydroxyethyl cellulose, derivates hydroxyethylcellulose, and mixtures thereof.

Useful crosslinked polymers include, but are not limited to, polymerscrossed linked with ions of borate, zirconate, and/or titanate.

Useful co-block polymers include, but are not limited to, polyethyleneoxide condensates of alkyl phenols, e.g., the condensation products ofalkyl phenols having an alkyl group containing from about 6 to about 20carbon atoms in either a straight chain or branched chain configuration,with ethylene oxide, the ethylene oxide being present in amounts equalto from about 1 to about 10 moles of ethylene oxide per mole of alkylphenol. The alkyl substituents in such compounds may be derived frompolymerized propylene, diisobutylene, octane, or nonane.

2. Surfactants

The pesticide formulations of the present disclosure comprise one ormore surfactants, also referred to as the surfactant system. Thesurfactant system is included to emulsify the composition, and/or to actas an adjuvant. The surfactant system comprises at least one surfactant,which may be an amphoteric surfactant, a zwitterionic surfactant, acationic surfactant, a nonionic surfactant, and optionally at least oneother surfactant, which may be an amphoteric surfactant, a zwitterionicsurfactant, a cationic surfactant, a nonionic surfactant, or acombination thereof. Such surfactants should be physically andchemically compatible with the essential components described herein, orshould not otherwise unduly impair product stability, aesthetics, orperformance.

Suitable surfactants for use in the fracking fluids of the presentdisclosure include one or more surfactants and/or co-surfactants ofFormula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; and an optional counterion associated withthe compound which, if present, is selected from the group consisting ofchloride, bromide, and iodide.

Suitable surfactants or co-surfactants may include one or more of any ofSurfactants 1-6 described herein.

The concentration of the surfactant system in the fracking fluidformulations may range from about 20 wt.% or greater, about 30 wt.% orgreater, about 40 wt. % or greater, or about 50 wt. % or lower, about 60wt. % or lower, about 70 wt. % or lower, or about 80 wt.% or lower, orwithin any range using these endpoints, by weight of the composition.

3. Thickening Agents

The fracking fluid formulations may include a water-soluble polymerhaving pendant hydrophobic groups, e.g., an acrylamide dodecyl acrylatecopolymer.

4. Viscoelastic Surfactant

Viscoelastic surfactants are generally defined as reagents that aresubstantially polymer free. Various vascoelastic surfactant fluids aredisclosed, for example, in U.S. Pat. Nos. 4,615,825, 4,725,372,4,735,731, CA-1298697, U.S. Pat. Nos. 5,551,516, 5,964,295, 5,979, 555and 6,232,274. One well-known polymer-free aqueous fracturing fluidcomprising a viscoelastic Surfactant, which has been commercialized bythe company group Schlumberger under the trademark ClearFRAC, and amixture of a quaternary ammonium salt, theN-erucyl-N,N-bis(2-hydroxyethyl)-N-methylammonium chloride, withisopropanol and brine, the brine preferably including 3% by weight ofammonium chloride and 4% by weight of potassium chloride.

5. Other Additives

Optional additives include compounds that can reduce or mitigate theeffect of solids such as sand that may become entrained in recoveredoils. These compounds include clay stabilization or sand stabilizationmaterials. Suitable clay stabilization or sand stabilization materialsinclude epoxy resins, polyfunctional cat ionic polymers. Such as poly(N-acrylamidomethyltriethyl ammonium chloride) or poly(vinylbenzyltrimethyl ammonium chloride).

Still other optional ingredients that may be added to the fluids of thepresent invention include, but are not limited to corrosion inhibitors,oxygen scavengers, and bactericides.

6. Method of Making

The method includes the step of combining the surfactant, or surfactantsystem, the polymer and/or, and/or a viscoelastic surfactant, withwater. This step may also include adding any additives described above.The aforementioned components and compounds may be added in any order toone or more of each other and in any amount and in one or moreindividual steps, e.g. in whole or in parts. In some methods of usingfracking fluids a significant amount of water is combined with the fluidupon injection into a well.

7. Method of Use

The fracking fluid formulations of the present disclosure may be inliquid form at room temperature and atmospheric pressure, with thecritical components solubilized therein.

If a concentrated fracking fluid is created it is intended to be mixedwith an aqueous medium, mixing with the aqueous medium may occur beforeand/or during use of the fluid. The concentrated formulation may beadded to a tank, before, simultaneously with or after, addition of theaqueous medium (water) to the tank. The concentrated fluid may bediluted significantly upon injection into a well, in which the wellitself already includes water. In some instances the fluid can beinjected into a well and followed by the introduction of water or insome instances additional water.

The water content in the diluted fracking formulation of the presentdisclosure may be from about 75 wt.% or greater, about 90 wt.% orgreater, about 99 wt.% or greater, or about 99.9 wt.% or greater, basedon the total weight of the diluted composition, and will ultimatelydepend on the amount of water needed to dilute fracking ingredient inthe concentrated pesticidal formulation of the present disclosure to thedesired concentration in the ready-to-use composition.

When mixed with and diluted in the aqueous medium, the components of thefluid are intended to be evenly distributed in the aqueous medium.

II. Formulations for Improved Oil Recovery (lOR)

Crude oil and/or naturally occurring gases are present within the poresof certain underground rocks. Typically, the initial or primary recoveryof crude oil and/or naturally occurring gasses, uses the pressure withinthe oil reservoir to drive the crude oil up through the wellbore. Duringprimary recovery only a small percentage of the crude oil in place isextracted, typically around 10% to 30% for most oil reservoirs.

Additional amounts of oil can be produced using waterflooding or gasinjection, known as secondary recovery. Secondary recovery is relativelyinexpensive and effective in producing up to an additional 5% to 20% ofcrude oil originally in the reservoir. Secondary recovery applies apressure to the oil reservoir to drive the crude oil up through thewellbore. However, primary and secondary recovery processes can extractless than half of the original oil in the reservoir. Much of the oilthat remains is discontinuous and is held in the rocks by very strongcapillary forces. Due to costs, many wells are not used after theprimary and secondary recovery processes have been completed.

Additional processes to increase the amount of the extracted oil aresometime referred to as enhanced oil recovery (EOR), or improved oilrecovery (IOR) or tertiary recovery. EOR serves to improve oildisplacement by reducing the interfacial tension (IFT) between the oiland water and by restoring the formation pressure to extract the crudeoil. The three major types of EOR include chemical or caustic flooding,miscible displacement using carbon dioxide (CO₂) injection orhydrocarbon injection, and thermal recovery using steam flooding orin-situ combustion.

Another method for improving oil recovery from a well is miscible gasflooding. Miscible gas flooding can be performed with carbon dioxide, toreduce the viscosity of the crude oil present in the subterraneanformation in order to increase the flow of hydrocarbons to a productionwell. Carbon dioxide, which acts as a solvent to reduce the viscosity ofthe crude oil, is an effective and relatively inexpensive miscible gas.During a miscible carbon dioxide flooding procedure the carbon dioxideis typically in the liquid and/or super critical phase. A method used toincrease the effectiveness of miscible gas flooding is to add a foamingsurfactant to the process.

Miscible displacement introduces miscible gases into the oil reservoir.Carbon dioxide is most commonly used because the gas reduces the oilviscosity and is less expensive than liquefied petroleum gas.

Thermal recovery introduces heat in the oil reservoir to cause the crudeoil to reduce its viscosity so that the oil flows toward the wellbore.During thermal recovery crude oil undergoes physical and chemicalchanges because of the effects of the heat supplied. Physical propertiessuch as viscosity, specific gravity and IFT are altered. The chemicalchanges involve different reactions such as cracking anddehydrogenation. However, it is costly to build a huge facility andpiping system to generate and transport large amounts of CO₂, and manyoil fields are located in areas not feasible to build such facilities.Also, CO₂ is mostly suitable for lighter oil fields. While thermalrecovery is only suitable for certain fields, particularly those withshallow depth and heavy oils flood, the injection may be followed by acheaper fluid, such as viscous water, and later water alone. Theinjection of the surfactants, viscous water and water involves thedisplacement of crude oil to the production well.

Still another tertiary recovery process involves chemical or causticflooding. This type of EOR uses an aqueous flood that includessurfactants, polymers and/or caustic compounds. The aqueous flooddecreases the IFT and pushes the crude oil from the rock. This crudeoil, in the form of immobile, capillary-trapped droplets, can bemobilized by injection of an aqueous flood with surfactants. Thesurfactants interact with the crude oil to form a micro-emulsion thatreduces the capillary trapping forces to a very low level. Oncemobilized, the crude oil forms a growing bank that leaves almost no oilbehind in the flooded part of the reservoir. After the aqueous flood,the injection may be followed by a cheaper fluid, such as viscous water,and later water alone. The injection of the surfactants, viscous waterand water involves the displacement of crude oil to the production well.Several patents and publications have discussed methods for enhanced oilrecovery using surfactants.

The invention involves the use of various amphoteric surfactants,including but not limited to, alkyl amidopropyl betaine sulfonates,alkyl dimethyl betainesulfonates, alkyl hydroxy sultaines sulfonates,alkyl sulfobetaine sulfonates and alkyl amine oxide sulfonates as lowadsorbing surfactants for applications including but not limited to,IOR, drilling, viscoelastic surfactant, acidizing, fracturing, foamingand production. The present invention involves using a sulfonating agentto react with the double bond of certain amphoteric surfactants,including but not limited to, alkylene amidopropyl betaines, alkylenedimethyl betaines, alkylene hydroxy sultaines, alkylene Sulfobetaines,and, alkylene amine oxide to make the corresponding sulfonatedamphoteric surfactants. The sulfonated amphoteric surfactants have beenfound to give ultra-low interfacial tension (IFT), viscoelasticproperties, compatibility with brines containing high salt and divalentions, and, low adsorption onto reservoir rock. Some embodiments of theinvention involve the use of various amphoteric surfactants, includingbut not limited to, alkyl amidopropyl betaine sulfonates, alkyl dimethylbetaine sulfonates, alkyl hydroxy sultaines sulfonates, alkylsulfobetaine sulfonates and alkyl amine oxide sulfonates as lowadsorbing surfactants for applications including but not limited to,IOR, drilling, viscoelastic surfactant, acidizing, fracturing, foamingand production.

1. Aqueous Injection Fluid/Carrier

Aqueous carriers that can be used in various formulations include butare not limited to water, brine, river water, synthetic brine and seawater. Brine often includes one or more salts such as mono and/ordivalent inorganic salts.

In many of the inventive formulations about 40 wt. % of the disclosedaqueous hydraulic fracturing compositions includes a carrier (e.g., thecarrier is present in the compositions in an amount in the range of atleast about 40 wt. % to about 99.88 wt. %, such as 40 wt. %, 50 wt. %,60 wt. %, 70 wt. %, 80 wt. %, 90 wt. %, 95 wt. %, or more). The carriercan be any suitable material that can dissolve the active ingredientsand co-ingredients and deliver the hydraulic fracturing composition to ahydraulic fracturing site. Water is a convenient carrier for liquidembodiments of the disclosed composition. The hydraulic fracturingcomposition may also be prepared as a gel, dip, foam, or spray.

2. Alkali

Alkalis are used as is known in the art to form “in situ” surfactantsthat act synergistically with the injected surfactant in some cases.Examples of alkalis that may be used to practice the invention includebut are not limited to sodium hydroxide, Sodium carbonate, sodiumborate, sodium silicate. Typically, alkali is used at concentration offrom 0 to about 5 wt. % of the injection fluid, although more may beadded as needed.

3. Viscosifiers

Examples of viscosifiers that may be used to practice the inventioninclude but are not limited to polyacrylamides, AMPS co-polymers,xanthan gum, other natural; and synthetic gums and polymers generallyknown to the art and used to increase the viscosity of the injectionfluid when necessary to control mobility and sweep efficiency.Generally, viscosifiers are used at concentrations of 0 to about 1 wt. %of the injection fluid, although may be used as needed.

4. Co-Solvents

Co-solvents may be used as are known to the art, to reduce the viscosityof the injection fluid, improve freeze-thaw or compatibility at highconcentrations. Exemplary co-solvents include but are not limited toC1-C8 alcohols, C1-C8 alcohol alkoxylates, and glycerin. Co-solvents areused at concentrations of 0 to about 50 wt. % of the injection fluid.

5. Surfactant and Co-Surfactants

Examples of surfactants and co-surfactants that may be used include oneor more compounds chosen from the group comprising anionic surfactants,cationic surfactants, amphoteric surfactants, nonionic surfactants.These have been used by those familiar with the art. Generally,co-surfactants are used at concentrations of 0 to about 5 wt. % of thetotal injection liquid formulation, although more may be added asneeded.

The IOR fluid formulations of the present invention comprise one or moresurfactants, also referred to as the surfactant system. The surfactantsystem may be used as a dispersing or wetting agent. The surfactantsystem may also be used as an emulsifier component to form a stableemulsion of the liquid fungicide formation when prepared foragricultural applications. The emulsifier component may also be used toform a stable emulsifiable concentrate. The surfactant system comprisesat least one surfactant, which may be an amphoteric surfactant, azwitterionic surfactant, a cationic surfactant, a nonionic surfactant,and optionally at least one other surfactant, which may be an amphotericsurfactant, a zwitterionic surfactant, a cationic surfactant, a nonionicsurfactant, or a combination thereof.

Suitable surfactants for use in the fungicidal formulations of thepresent disclosure include one or more surfactants and/or co-surfactantsof Formula I,

wherein R¹ and R may be the same or different, and comprise at least onegroup selected from the group consisting of C₁-C₆ alkyl, optionally theC₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfur atomsor groups that include at least one of these atoms, and the alkyl chainmay be optionally substituted with one or more substituents selectedfrom the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; and an optional counterion associated withthe compound which, if present, is selected from the group consisting ofchloride, bromide, and iodide.

Suitable surfactants or co-surfactants may include one or more of any ofSurfactants 1-6 described herein.

The total amount of the one or more surfactants in the fungicidalformulation may be about 1 wt.% or greater, about 5 wt.% or greater,about 10 wt.% or greater, or about 15 wt.% or less, about 20 wt.% orless, about 25 wt.% or less, about 30 wt.% or less, about 35 wt.% orless, or within any range using these endpoint

6. Co-Emulsifier or Co-Surfactant

Some embodiments of the invention include the use of, foam-formingsurfactant compositions including surfactant mixtures of at least onesurfactant according to the disclosure as well at least one additionalsurfactant such as, sulfosuccinamate surfactant with at least onesulfosuccinate surfactant, selected from monoester sulfosuccinatesurfactants and diester sulfosuccinate surfactants, and blends thereof,as well as these surfactant mixtures blended with further surfactantswhich are, inter alia, alkanolamides, alkyl sulfates, alpha-olefinsulfonates, betaines, fatty acid soaps, fatty alcohol alkoxylates,ethoxylated sorbitan esters, and sulfobetaines produce increased amountsof stable foams that exhibit, inter alia, extended foam half-life inseawater, seawater/diesel mixtures, and brine. These surfactant mixturesmay optionally comprise a solvent, which is preferably water, or anaqueous solution that also comprises salts, foam boosters such asxanthan gum, oils which may be hydro carbon oils or vegetable oils, andthickeners or preservatives. Compared to foam-forming compositions ofthe prior art, these formulations offer improvements in the amount offoam generated, the foam stability and the lifetime of the foam.

Some commercially desirable foam-forming surfactant compositions asdescribed herein offer improved foaming performance in diverse aqueousmedia including seawater (usually containing an average mass faction ofdissolved salts about 3.5%, the largest part of which is sodiumchloride) and brine (i.e. aqueous salt solutions containing typicallymass fractions of up to 12%, such as from 0.1% to 11%, of dissolvedsalts of monovalent and divalent cations). The improved surfactantcompositions are functional both at ambient temperature (typically 23°C.), and lower temperatures, such as from 1° C. up to 23° C. or elevatedtemperatures, such as more than 23° C. up to 95° C. This includescreating a formulation that offers greater overall foam volume, improvedfoam stability and maximum lifetime of the foam (i.e., foam half-life,the time required for 50% of the volume of the liquid media to separateout of the original foam). Moreover, the foam-forming surfactantcompositions as fully described herein advantageously offer improvedperformance at lower concentrations thereby reducing environmental andworker exposure, while simultaneously exhibiting a lower tendency toform oil in water emulsions, which is also advantageous as it wouldsimplify oil recovery in production.

III. Emulsions and/or Foams

Aqueous foam-forming surfactant compositions can be made therefrom byaddition of water or aqueous salt solutions, such as seawater or brine,optionally in mixture with a hydrocarbon or a mixture of hydrocarbons,and effective foam-forming amounts of one or more foam formingsurfactant composition described herein. It is also possible to usesupercritical gases as liquid media, whereto effective foam-formingamounts of the foam-forming surfactant compositions described herein areadded. The types of surfactants detailed in the invention includeanionic surfactants, mixtures of two or more anionic surfactants, andcombinations of any of these with cationic, amphoteric, zwitterionic,and nonionic surfactants, and the gases may include, for example, one ormore of air, carbon dioxide, nitrogen, methane, or other natural andproduced gases.

One method for improving oil recover from a well is miscible gasflooding. Miscible gas flooding can be performed with carbon dioxide, toreduce the viscosity of the crude oil present in the subterraneanformation in order to increase the flow of hydrocarbons to a productionwell. Carbon dioxide, which acts as a solvent to reduce the viscosity ofthe crude oil, is an effective and relatively inexpensive miscible gas.During a miscible carbon dioxide flooding procedure, the carbon dioxideis typically in the liquid and/or super critical phase. A method used toincrease the effectiveness of miscible gas flooding is to add a foamingsurfactant to the process.

In one aspect of the invention includes methods for recovering petroleumor natural gas from a reservoir or subterranean oil- or gas-bearinggeological formation during the injection of a gas using foam formingsurfactant compositions according to the invention. The methodscontemplated by the present invention include contacting the oil or gasin the formation with any one or more of the foam-forming surfactantcompositions and the injected gas so as to assist in the recovery ofoil. The methods contemplated herein for recovery of petroleum ornatural gas using the foam-forming surfactant compositions describedherein can be performed as part of any one or more of the primary,secondary, or tertiary recovery techniques standard to the industry.Foam-forming surfactants composition of the invention can be used assolutions in a solvent or liquid vehicle, wherein the solvent isselected from water, aqueous salt solutions, liquefied gases,supercritical gases, and mixtures of these. Typically, the surfactant isincorporated into the aqueous media and a foam is created. If an aqueoussalt solution is used as solvent, an aqueous foam forming surfactantcomposition is obtained, wherein the combination of the foam-formingsurfactant composition and the water or aqueous salt solution preferablycomprises a mass fraction of at least 0.2%, and preferably, up to 10%,of dissolved inorganic salts, and foam can be generated therefrom byintimate mixing with a gas in a foam generator. It is also possible togenerate a foam in situ through introduction under pressure ofalternating slugs of a gas and of the foam-forming surfactantcomposition into a subterranean oil- or gas-bearing geological formationwhich, in many cases, also contains water or aqueous salt solutions. Thesame mass fraction of at least 0.2%, and preferably, up to 10%, ofdissolved inorganic salts is usually obtained thereby.

The roles performed by emulsion in the recovery of hydrocarbons such asoils and natural gas include foams which may be used, for example, toenhance recovery of a gas or an oil from a well source. In someembodiment that emulsion may be formed with the oil or gas to berecovered from for example, a well or from a product of a bio process.In some embodiments the invention surfaces disclosures herein are usedto create the emulsion for example a foam. In still other embodimentssurfactants may be used to break an emulsion which includes an oil or agas to be recovered.

Foams may be formed by adding an effective amount of at least oneanionic surfactant present within a high salinity foamed fluidcomposition in an effective amount to generate an IFT as low as 10 - mN/ m. The anionic surfactant may be an inventive surfactant or asulfonate surfactant and / or a sulfate surfactant. The foamed fluidcomposition may be used to perform an operation, including but notlimited to, a gas lift operation, a drilling operation, a completionoperation, a stimulation operation, a fracturing operation, an injectionoperation, an enhanced oil recovery operation, and combinations thereof.

Foamed fluids are used in a variety of applications during the recoveryof hydrocarbons from subterranean reservoirs. Foamed fluids includefluids that include a base fluid, a foaming agent, and a gas, includingbut not limited to nitrogen, carbon dioxide, air, methane, and the like.The base fluid may be foamed to reduce the amount of base fluidrequired, to reduce the amount of fluid loss to the formation, and/or toprovide enhanced proppant suspension in fracturing fluids. ‘Foamingagent’ is defined herein to be an agent for facilitating the foaming ofa base fluid when gas is mixed therewith.

Foamed fluids may also be used during stimulation operations (e.g.unloading of gas wells) to displace any pre-existing fluid and/orformation fluid present in the wellbore. ‘Pre-existing fluid’ is definedherein as a fluid present in the subterranean reservoir wellbore priorto the introduction of the foaming additive and/or the foamed fluidcomposition into the subterranean reservoir wellbore. ‘Formation fluid’is defined herein to be any fluid produced from an oil bearingsubterranean formation including but not limited to oil, natural gas,water, and the like. Formation fluids may be considered pre-existingfluids, but pre-existing fluids may not necessarily be a formationfluid. For example, other downhole fluids may be injected into thesubterranean reservoir wellbore and are still present in the wellborewhen the foaming additive is introduced into the wellbore. Thus, thedownhole fluid (e.g. drilling fluid, completion fluid, fracturing fluid,injection fluid, etc.) may be the ‘base fluid’ upon introduction of thefoaming additive and gas into the subterranean reservoir wellbore.

The base fluid of a foamed fluid may be a drilling fluid, a completionfluid, a stimulation fluid, a fracturing fluid, an injection fluid, andcombinations thereof. Non-limiting examples of the use of such fluidsmay involve unloading oil or gas wells, enhanced oil recovery operation,heavy oil recovery, a drilling operation, a fracturing operation,pressure pumping, cementing, acidizing or other stimulation operation,and the like.

A non-limiting example of a foamed drilling fluid may be one where thedrilling operation requires the drilling fluid to have a low density;for example, the density of the foamed drilling fluid may range fromabout 2.0 ppg (about 0.24 g/cm³) independently to about 8.0 ppg (about0.96 g/cm³)

Drilling fluids are typically classified according to their base fluid.In water-based fluids, solid particles are suspended in a continuousphase consisting of water or brine. Oil can be emulsified in the water,which is the continuous phase. “Water-based fluid” is used herein toinclude fluids having an aqueous continuous phase where the aqueouscontinuous phase can be all water or brine, an oil-in-water emulsion, oran oil-in-brine emulsion. Brine-based fluids, of course are water-basedfluids, in which the aqueous component is water based. Oil-based fluidsare the opposite or inverse of water-based fluids.

“Oil-based fluid” is used herein to include fluids having a non-aqueouscontinuous phase where the non-aqueous continuous phase is all oil, anon-aqueous fluid, a water-in-oil emulsion, a water-in-non-aqueousemulsion, a brine-in-oil emulsion, or a brine-in-non-aqueous emulsion.In oil-based fluids, solid particles are suspended in a continuous phaseconsisting of oil or another non-aqueous fluid. Water or brine can beemulsified in the oil; therefore, the oil is the continuous phase. Inoil-based fluids, the oil may consist of any oil or water-immisciblefluid that may include, but is not limited to, diesel, mineral oil,esters, refinery cuts and blends, or alpha-olefins. Oil-based fluid asdefined herein may also include synthetic-based fluids or muds (SBMs),which are synthetically produced rather than refined fromnaturally-occurring materials. Synthetic-based fluids often include, butare not necessarily limited to, olefin oligomers of ethylene, estersmade from vegetable fatty acids and alcohols, ethers and polyethers madefrom alcohols and polyalcohols, paraffinic, or aromatic, hydrocarbonsalkyl benzenes, terpenes and other natural products and mixtures ofthese brine types.

One type of drilling operation involves cementing where cement is pumpedinto place in a wellbore. Cementing operations may be used to seal anannulus after a casing string has been run, to seal a lost circulationzone, to set a plug in an existing well from which to push off withdirectional tools, or to plug a well so that it may be abandoned. Beforecementing operations commence, the volume of cement to be placed in thewellbore is determined, as well as the physical properties of the slurryand the set cement needed, including density and viscosity. The drillingfluids may be displaced to place the cement in the wellbore. In carryingout primary cementing, as well as remedial cementing operations inwellbores, the cement slurries utilized must often be light-weight toprevent excessive hydro-static pressure from being exerted onsubterranean formations penetrated by the wellbore. As a result, avariety of light-weight cement slurries have been developed and used,including foamed cement slurries.

In addition to being light-weight, a foamed cement slurry containscompressed gas, which improves the ability of the slurry to maintainpressure and to prevent the flow of formation fluids into and throughthe slurry during its transition time, i.e., the time during which thecement slurry changes from a true fluid to a hard set mass. Othersurfactants, besides those used as foaming agents, may be used as foamstabilizers for preventing the foam slurries from pre-maturelyseparating into slurry and gas components, and may also be added to theslurry. foamed cement slurries may have low fluid loss properties.

There are a variety of functions and characteristics that are expectedof completion fluids. The completion fluid may be placed in a well tofacilitate final operations prior to initiation of production.Completion fluids are typically brines, including chlorides, bromides,formates, but may be any non-damaging fluid having proper density andflow characteristics. Suitable salts for forming the brines include, butare not necessarily limited to, sodium chloride, calcium chloride, zincchloride, potassium chloride, potassium bromide, sodium bromide, calciumbromide, zinc bromide, sodium formate, potassium formate, ammoniumformate, cesium formate, and mixtures thereof. Chemical compatibility ofthe completion fluid with the reservoir formation and fluids can be veryimportant. Chemical additives, such as polymers and surfactants areknown in the art for being introduced to the brines used in wellservicing fluids for various reasons that include, but are not limitedto, increasing viscosity, and increasing the density of the brine.

Servicing fluids, such as remediation fluids, stimulation fluids,workover fluids, and the like, have several functions andcharacteristics necessary for repairing a damaged well. Such fluids maybe used for breaking emulsions already formed and for removing formationdamage that may have occurred during the drilling, completion and/orproduction operations. The terms “remedial operations” and “remediate”are defined herein to include a lowering of the viscosity of gel damageand/or the partial or complete removal of damage of any type from asubterranean formation. Similarly, the term “remediation fluid” isdefined herein to include any fluid that may be useful in remedialoperations. A stimulation fluid may be a treatment fluid prepared tostimulate, restore, or enhance the productivity of a well, such asfracturing fluids and/or matrix stimulation fluids in one non-limitingexample.

Hydraulic fracturing is a type of stimulation operation, 30 which usespump rate and hydraulic pressure to fracture or crack a subterraneanformation in a process for improving the recovery of hydrocarbons fromthe formation. Once the crack or cracks are made, high permeabilityproppant relative to the formation permeability is pumped into thefracture to prop open the crack. When the applied pump rates andpressures are reduced or removed from the formation, the crack orfracture cannot close or heal completely because the high permeabilityproppant keeps the crack open. The propped crack or fracture provides ahigh permeability path 40 connecting the producing wellbore to a largerformation area to enhance the production of hydrocarbons.

Another type of stimulation operation is one where the oil or gas wellis ‘unloaded’. In most gas wells, water and/or condensate is producedalong with gas. In mature gas wells, decreasing formation pressures andgas velocities gradually 65 cause the wells to become “loaded” withliquids. Because of the difficulties in treating liquid-loaded wellswith higher condensate cuts, operators may use a variety of methods toprevent liquid loading in marginal gas wells.

Unloading an oil or gas well may be necessary when a primary productiontechnique (i.e., use of only the initial formation energy to recover thecrude oil), followed by the secondary technique of waterflooding,recovers only a small percentage of the original oil in place present inthe formation. The average recovery factor is around 25 to 35% for oilfields and around 70% for gas fields after secondary recoveryoperations. Gas well production and oil well production systems aregenerally limited in their production due to the load of oil and waterin the flowlines.

Gas lift and/or deliquification of wells may enable wells with liquidloading issues to be returned to continuous flowing status, enhance theflow of a current producing well, restart a well, and combinationsthereof. Typically, as the oil and/or gas is produced from thereservoir, the pressure of the reservoir formation decreases and theproduction declines. In addition, the production of the well may declineover time due to completion issues, and the well may become difficult torestart. A method commonly used to deliquify or ‘unload’ these wells isthrough the application of chemical foaming agents.

The use of foam generated in situ by surfactant-alternating-gas (SAG)injection is described as a substitute for polymer drive in analkaline/surfactant/polymer (ASP) enhanced oil recovery (EOR) process inR. F. Li, et al., “Foam Mobility Control for Surfactant Enhanced OilRecovery,” SPE 113910, SPE/DOE Symposium on 20 Improved Oil Recovery,Tulsa, Okla., SPE Journal, March, 2010.

Micellar, alkaline, soap-like substances, and the like may be used toreduce interfacial tension between oil and water in the reservoir andmobilize the oil present within the reservoir; whereas, polymers, suchas polyacrylamide or polysaccharide may be employed to improve themobility ratio and sweep efficiency, which is a measure of theeffectiveness of an EOR operation that depends on the volume of thereservoir contacted by the injected fluid.

In an alternative non-limiting embodiment of the method, the method mayinclude unloading an oil or gas well within a subterranean oil-bearingformation by introducing a foamed fluid composition into thesubterranean reservoir wellbore having a pre-existing fluid therein. Thefoamed fluid composition may have or include a base fluid, a gas, atleast one anionic surfactant, and at least one second surfactantselected from the group consisting of cationic surfactants, nonionicsurfactants, zwitterionic surfactants, and combinations thereof. The atleast one anionic surfactant is selected from the group consisting ofsulfonate surfactants and/or sulfate surfactants, where the anionicsurfactant comprises a C20-C24 carbon chain and an internal olefin. Thefoamed fluid composition has a salinity equal to or greater than 30,000TDS. The surfactants are present in an amount effective to foam thecomposition. The method further comprises at least partially displacingthe pre-existing fluid within the subterranean reservoir wellbore.

There is further provided, in another form, a foamed fluid compositionhaving a base fluid, a gas, at least one anionic surfactant, and atleast one second surfactant. The base fluid may be or include anoil-based fluid, an aqueous-based fluid, and combinations thereof. Theanionic surfactant has a hydrophobic chain of at least 20 carbon atoms,where the anionic surfactant is a sulfonate surfactant, a sulfatesurfactant, or combinations thereof. The anionic surfactant is presentin the foamed fluid composition in an amount effective to give an IFTbetween about 10- 1 mN/m and about 10- 3 mN/m. The at least one secondsurfactant includes, but is not necessarily limited to, cationicsurfactants, nonionic surfactants, zwitterionic surfactants, andcombinations thereof. The foamed fluid composition has a salinity equalto or greater than 30,000 total dissolved solids (TDS).

In another non-limiting embodiment of the foamed fluid composition, theanionic sulfonate surfactant(s) may have or include a C20-C24 carbonchain and an internal olefin therein, and the amount of the at least oneanionic surfactant ranges from about 1 vol % to about 50 vol % based onthe total foamed fluid composition.

There is provided, in one form, a method that may include performing anoperation with a foamed fluid composition. The foamed fluid compositionmay have or include a base fluid, a gas, at least one anionic surfactanthaving a hydro-phobic chain of at least 20 carbon atoms, where theanionic surfactant is selected from the group consisting of sulfonate.

1. Surfactant

Suitable surfactants for use in the herbicide formulations of thepresent disclosure include one or more surfactants and/or co-surfactantsof Formula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; and an optional counterion associated withthe compound which, if present, is selected from the group consisting ofchloride, bromide, and iodide.

In particular, suitable surfactants or co-surfactants may include one ormore of any of Surfactants 1-6 described herein.

2. A Second Surfactant

At least one anionic surfactant having a hydrophobic chain of 12 to 24carbon atoms, where the anionic surfactant is selected from the groupconsisting of sulfonate surfactants, sulfate surfactants, andcombinations thereof, and at least one second surfactant selected fromthe group consisting of cationic surfactants, nonionic surfactants,zwitterionic surfactants, and combi-nations thereof.

3. A Base Fluid

The base fluid may be an oil-based fluid or a water-based fluid selectedfrom a group consisting of a drilling fluid, a completion fluid, astimulation fluid, a fracturing fluid, a gas well deliquification fluid,a coiled tubing operations fluid, a recycled drilling fluid, a servicingfluid, a well clean-out fluid, a well intervention fluid, a capillarycoiled tubing fluid and combinations thereof.

4. A Gas

Any suitable gas known in the art can be admixed with any appropriateliquid portion of the liquid formulation. Such gases include, but arenot limited to, air, nitrogen carbon dioxide, natural gas, and anycombination thereof.

IV. Fluids for Recovering Bio Oils

Bio based oils include edible oils from naturally occurring sources area staple of human nutrition and until relatively recently a source oflight and even energy. Naturally occurring sources of oil include seeds,and fruits, some which are cultivated essentially as sources of oil.Sources of bio based oils that may be used for fuel including bio dieselfuel include soybeans naturally occurring and bio-engineered algae. Anyformulations and/or processes that can be used to increase the recoveryand/or quality of the recovered oils is beneficial.

Other sources of bio based oils include stillage from the fermentationof feed stocks such a corn and from the processing of oil rich plantssuch soybeans and algae. Some embodiments of the invention includeformulations for aiding in the extraction of an emulsified oil from anoil and water emulsion. The composition may include a non-ionicsurfactant selected from alkoxylated plant oils, alkoxylated plant fats,alkoxylated animal oils, alkoxylated animal fats, alkyl poly glucosides,alkoxylated glycerols, and mixtures thereof. The composition may includesilicon containing particles. Some methods for recovering oil from acorn to ethanol process is also provided. These methods may include thesteps of adding the composition to a process stream of the corn toethanol process, and extracting oil from the process stream.

Formulations for the recovery of edible oil include only reagentscharacterized as generally regarded as safe (GRAS) by regulatoryagencies such as the United States Department of Agriculture and theUnited States Food and Drug Administration.

Sources of bio based oils that may be used for fuel including bio dieselfuel include soybeans naturally occurring and bio-engineered algae.

Most commercial corn oil is produced by front end fractionation of corngerm during the wet mill corn process. Recently, a new source of cornoil has arisen as a by-product of the dry-mill process used in theethanol industry. Dry milling is a process requiring less energy andless capital investment than wet-milling. Though corn oil captured atthe tail-end of a dry mill process is not suitable for food use, it canbe used as a biodiesel feedstock.

1 Aqueous Components

The aqueous component may include for example, fresh water, sea water,most commonly the aqueous phase comprises water that includes one ormore inorganic salts.

2. Supercritical Gases

Some inventive foams include super critical gasses, for example, carbondioxide. Supercritical carbon dioxides (CO₂) is a fluid state of the gaswherein the gas is held at or above its critical temperate and criticalpressure. Gases in this state exhibit some properties midway been theproperties of a gas and a liquid. Supercritical carbon dioxide exists ata temperature at or above about 31.1° C. and a pressure above about 7.39MPa.

3. Surfactants

Suitable surfactants for use in the herbicide formulations of thepresent disclosure include one or more surfactants and/or co-surfactantsof Formula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; and an optional counterion associated withthe compound which, if present, is selected from the group consisting ofchloride, bromide, and iodide.

In particular, suitable surfactants or co-surfactants may include one ormore of any of Surfactants 1-6 described herein.

The aforementioned surfactants can be combines with other surfactantincluding for example, sulfosuccinaamate type surfaces of the formula:R-NX-CO-CHY¹-CHY²- CO-O-M^(4+,) wherein Y⁻¹ is H and Y² is (SO₃M³⁺, orY⁻¹ is (SO₃M³⁺) and Y² is H. M³⁺ and M⁴⁺ are cations, and may be thesame or may be different, and are selected from groups 1 and 2 of thePeriodic Table of the Elements, consisting of the alkali metals, and theearth alkali metals, preferably from Li+, Na+, K+, and also fromammonium NH⁴+; R is a linear or branched or cyclic aliphatic radicalhaving from eight to twenty-four carbon atoms, and optionally, one ormore carbon-carbon double bonds, or a mixture of two or more of Suchradicals. X can be a hydrogen atom, or can be an alkylcarboxylate group-(CRR)-COOM²⁺, where R′ and R may both by H, or R is Hand R is —CH COOM³⁺, where M³⁺, and M⁺, are cations, and may be the same or may bedifferent, and are selected from groups 1 and 2 of the Periodic Table ofthe Elements, consisting of the alkali metals, and the earth alkalimetals, preferably from Li, Na⁺, K⁺, and also from ammonium NH.Particularly preferred alkali metal ions for M³⁺, M⁺, M²⁺, and M⁴⁺are,independently from each other, the sodium cation, Na⁺, and the potassiumcation, K⁺

Still other surfactants optionally included in the indicated separationaid composition can be, for example, nonionic surfactants, cationicsurfactants, or anionic surfactants. The surfactant (which can be one ormore) can be a nonionic surfactant, for example, ethoxylated castor oil,an ethoxylated sorbitan ester, a PEG, a poloxamer, an acetylenic glycol,or a sulfonate, or combinations thereof. The nonionic surfactants canbe, for example, nonionic polyethylene glycols, such as ethoxylate ofcarboxylic acids, ethoxylate of mono-, di- or triglycerides, ethoxylateof mono-, di- or triesters of sorbitan or ethoxylate of fatty alcohols.The ethoxylated sorbitan esters can be commercially obtained as TWEEN orpolysorbate series surfactant. Other suitable nonionic surfactants aremono-, di- or triglycerides based on fatty acids having 12-22 carbonatoms, or mono-, di- or triesters of sorbitan based on fatty acidshaving 12-22 carbon atoms. Commercial sources of the nonionic Surfactantwhich can be used in separation aids of the present invention include,for example, Lumisorb Polysorbates from Lambent Technologies Corporation(Gurnee, Ill. USA). The nonionic surfactant may be at least onepoloxamer. Poloxamers can be nonionic triblock copolymers that comprisea central block of a hydrophobic poly alkyleneoxide block, which isflanked on both sides with hydrophilic polyalkyleneoxide blocks.Poloxamers are commercially available that are food grade. A commercialSource of poloxamers are, for example, PLURONIC®copolymers from BASFCorporation (Florham Park, N.J., U.S.A.).

The water solubility of the surfactants, such as the nonionicsurfactants, can be related to their hydrophilic-lipophilic balance(HLB) value or number. The nonionic surfactants can have an HLB value ofat least about 6, or at least about 9, or at least about 12, or fromabout 6 to 20, or from about 7 to about 19, or from about 8 to about 18,or from about 9 to about 17, or from about 10 to about 16, or othervalues. The water solubility of nonionic surfactants can be related totheir hydrophilic-lipophilic balance (HLB) value or number. The HLBvalue can be calculated in a conventional manner. For example, the HLBvalue of a nonionic surfactant can be calculated by dividing themolecular weight percent of the hydrophilic portion of the nonionicsurfactant by five. For example, a nonionic surfactant containing 80mole 96 hydrophilic portion (total) would have an HLB value calculatedto be 16 (i.e., 80/5-16). HLB values that exceed 20 are relative orcomparative values.

Some inventive formulations may include one or more surfactants in anamount of about 0 wt.% or greater, about 2 wt.% or greater, about 4 wt.%or greater, about 6 wt.% or greater, about 8 wt.% or greater, or about10 wt.% or lower, about 12 wt.% or lower, about 14 wt.% or lower, about16 wt.% or lower, or within any range using these endpoints.

4. Oils

Oils that may be used to practice the invention include, alkoxylatedplant oils selected from the group consisting of ethoxylated castor oil,ethoxylated soy-bean oil, ethoxylated palm kernel oil, ethoxylatedalmond oil, ethoxylated corn oil, ethoxylated canola oil, ethoxylatedrapeseed oil, and ethoxylated coconut oil.

The oil included in the indicated separation aid can be, for example,mineral oil, triglyceride vegetable oil, hydrocarbon oil, or anycombination thereof. The mineral oil can be, for example, white mineraloil or mineral seal oil. Examples of the mineral oil can be theatmospheric residue oil obtained in the distillation of crude oil,vacuum gas oil, and vacuum residue oil obtained by vacuum distillationof the atmospheric residue oil, their hydrotreated oils, pyrolysis oils,and or their mixtures. Among these mineral oils, the atmospheric residueoil, vacuum residue oil, and their hydrotreated products or pyrolysisproducts are referred to as residue oils in the present invention. Thetriglyceride vegetable oil can be, for example, triglyceride corn oil.The hydrocarbon oil can be, for example, white mineral oil, or anycombinations thereof. Commercial sources of the oil which can be used inseparation aids of the present invention include, for example, ClarionWhite Mineral Oil 70, CITGO Petroleum (Houston, USA).

5. Lecithin

The lecithin used in the separation aid can be natural origin, modifiedorigin, or synthetic. The lecithin which can be used in the presentinvention can be lecithin derived from any plant, animal or microbialsource. Suitable lecithin starting materials are commercially available,and include available soybean lecithin and yolk lecithin products.Lecithin can be obtained from natural sources such as egg yolk, andplants such as soybean, maize, rapeseed, and the like where it is aby-product of vegetable oil refinement. Soybean oil is the largestsource of commercial lecithin. The composition of commercial lecithindepends on the source, methods of preparation, and degree ofpurification, but in the most pure form it is comprised of mainlyphosphatides. Commercial lecithin, for example, is a co-product of oilprocessing obtained during degumming step. For example, soybean lecithinis a complex mixture and comprises of phospholipids and triglycerides,with minor amounts of other constituents like phytoglycolipids,phytosterols, tocopherols and fatty acids. The major phospholipidspresent in vegetable lecithins are phosphatidylcholine,phosphatidylethanolamine and phosphatidylinositol. The egg yolk lecithincontains phosphatidyl choline and phosphatidylethanolamine as majorphospholipids. Lecithin can be extracted chemically (using hexane) ormechanically from readily available sources such as soy beans. Lecithinhas low solubility in water. In aqueous solution, its phospholipids canform either liposomes, bilayer sheets, micelles, or lamellar structures,depending on hydration and temperature. This results in a type ofmaterial that is usually classified as amphipathic. As used herein,“modified lecithin” refers to, but is not limited to, acetylation,hydroxylation, hydrogenation, hydrolysis products of lecithin,chlorination, bromination, iodination, halogenation, phosphorylation andsulfonation, as well as any other modification known to those in theart. Acetylated lecithins can be produced, for example, using acarboxylic acid anhydride like acetic anhydride for the acetylation ofphospholipids from vegetable lecithins, such as shown in U.S. Pat. No.3,301,881, which is incorporated herein by reference in its entirety. Anenzymatic process can be used for the preparation of an acetylatedphospholipid from vegetable lecithins such as soy bean lecithin,rapeseed lecithin, and animal lecithins like egg yolk lecithin or purephosphatidylethanolamine isolated from the above lecithins. Commerciallecithins can be acetylated, for example, by using vinyl acetate asacylating agent in presence of lipase from Mucor-Miehei having1.3-position specificity as catalyst, such as shown in U.S. Pat. No.6,403,344, which is incorporated herein by reference in its entirety. Inacetylated lecithin, for example, acetylation occurs primarily on theamino group of phosphatidylethanolamine. The extent of acetylation onthe modified lecithin, if used, can be partial or complete. The extentof acetylation on a modified lecithin can be, for example, from about 5%to 100%, or from about 10% to about 99%, or from about 15% to about 95%,or from about 20% to about 90%, or from about 25% to about 75%, or othervalues. Lecithin additionally contains a number of chemical functionalgroups that make it susceptible to a variety of chemical reactions.These groups include carbon-carbon double bonds, esters, phosphonateesters, amines and hydroxyl groups. Modification may also result ininteresterified lecithin. Additionally, lecithins may be enzymemodified. As used herein, “phosphatides” (Phospholipids) refers to, butare not limited to, mixtures of phosphatidylcholine, phosphatidylethanolamine, phosphatidyl serine, phosphatidyl inositol, phosphatidicacid, N-acylphosphatidylethanolamine and other related minorconstituents. Commercial sources of lecithin or modified lecithin whichcan be used in separation aids of the present invention include, forexample, Solec HR2B from Solae LLC (Memphis, Tenn. USA).

6. Silica

For example, the separation aid can contain silica, such as fumedsilica. The fumed silica can be hydrophobic or hydrophilic. Fumed silicais food grade and can be more desirable for this reason. Fused, fumedsilica can be contained in the separation aid in an amount, for example,of from about 1 wt % to 10 wt %.

7. Water-Insoluble Solvents and Oils

Suitable water-insoluble immiscible organic solvents include thosederived from or made from natural, non-petroleum sources such as, forexample, plants and animals, and include, vegetable oils, seed oils,animal oils and the like, such N,N-dimethylcaprylamide(N,N-dimethyloctanamide), N,N-dimethylcapramide(N,N-dimethyldecanamide), and mixtures thereof, which are availablecommercially as Agnique® AMD 810 and Agnique® AMD 10, from BASF Corp.(Florham Park, N.J.), Genegen® 4166, Genegen® 4231 and Genegen® 4296,from Clariant (Charlotte, N.C.), Hallcomid M-8-10 and Hallcomid M-10,from Stepan (Northfield, III.), and Amid DM10 and DM810 from AkzoNobel(Chicago, III.). Additional examples of naturally derived organicsolvents include the morpholine amides of caprylic/capric fatty acids(C8/C10) which are commercially available as JEFFSOL® AG-1730 Solventfrom Huntsman International LLC (The Woodlands, Tex.).

Other suitable water-insoluble solvents may include aromatichydrocarbons, mixed naphthalene and alkyl naphthalene fractions,aromatic solvents, particularly alkyl substituted benzenes such asxylene or propylbenzene fractions, and the like; C1-C6 esters of fattyacids derived from vegetable, seed or animal oils such as, methylcaproate, methyl caprylate, methyl caprate, methyl laurate, methylmyristate, methyl palmitate, methyl stearate, methyl oleate, methyllinoleate, methyl linolenate, and the like; ketones such as isophoroneand trimethylcyclohexanone (dihydroisophorone); acetate esters such as,methyl, ethyl, propyl, butyl, pentyl, hexyl, or heptyl acetate, and thelike; and cyclic alkyl carbonates such as propylene carbonate andbutylene carbonate, which are available as the JEFFSOL® alkylenecarbonates from Huntsman (The Woodlands, Tex.), and dibutyl carbonate,also from Huntsman, and mixtures of any of the water immiscible organicsolvents described herein.

The water-insoluble solvent may be present in the herbicidal formulationin an amount of about 0 wt.% or greater, about 10 wt.% or greater, about20 wt.% or greater, or about 30 wt.% or lower, about 40 wt.% or lower,about 50 wt.% or lower, or within any range using these endpoints.

8. Water

Water may be present in the formulations of the present disclosure toserve as both an aqueous solvent and a carrier for the ingredients inthe described compositions. Some formulations of the present disclosuremay include water in an amount of about 200 g/L or greater, about 300g/L or greater, about 400 g/L or greater, or about 500 g/L or lower,about 600 g/L or lower, about 700 g/L or lower, about 800 g/L or lower,or within any range using these endpoints.

9. Other Additives

The herbicidal formulation may include one or more additional compatibleingredients. These additional ingredients may include, for example, oneor more pesticides or other ingredients, which may be dissolved ordispersed in the composition and may be selected from acaricides,algicides, antifeedants, avicides, bactericides, bird repellents,chemosterilants. Also, any other additional ingredients providingfunctional utility such as, for example, antifoam agents, antimicrobialagents, buffers, corrosion inhibitors, dispersing agents, dyes,fragrants, freezing point depressants, neutralizing agents, odorants,penetration aids, sequestering agents, stabilizers, sticking agents,viscosity-modifying additives, water soluble solvents and the like, maybe included in these compositions.

When the formulations are used in combination with the additional activeingredients such as, the compositions described herein can be formulatedwith the other active ingredient or active ingredients as premixconcentrates, tank-mixed in water with the other active ingredients.

10. Method of Making

The formulations of the present disclosure may be prepared by the stepsof: 1) preparing a solution of in an organic solvent and a surfactant;2) adding the solution prepared in step 1) to a concentrated solution ofa water-soluble salt in water with good mixing to form a clear solution;and 3) optionally, adding any additional compatible active or inertingredients.

Alternatively, the formulations of the present disclosure may beprepared by the steps of: 1) providing an oil, optionally, mixing itwith the organic solvent and a surfactant; 2) adding the compositionprepared in step 1) to a concentrated solution of a water-soluble saltwith good mixing to form a clear solution; and 3) optionally, adding anyadditional compatible active or inert ingredients.

Suitable water compatible ingredients that may be added to theformulations include, but are not limited to, water soluble or waterinsoluble dispersing surfactants, such as the surfactants of the presentdisclosure, water insoluble active ingredients and optionally, otherinert ingredients such as pH buffers, wetting agents, antifreeze agents,antifoam agents, and biocides.

11. Method of Use

The solution may be added to naturally occurring sources of oil such assoy bean mash, or algae bio-mass, or to synthetic sources of oils suchas stillage from corn ethanol producing processes. Once mixed with thesource of bio oil may be separated from the oil sources by any meansknown in the art including, for example, settling, heating, cooling,freezing, and the like.

12. Surfactants

The foaming formulation for which may include one or more surfactantschosen from one or more surfactant classes, collectively referred to asthe surfactant system.

Suitable surfactants for use in the inv formulations of the presentdisclosure include one or more surfactants and/or co-surfactants ofFormula I,

wherein R1 and R2 may be the same or different, and comprise at leastone group selected from the group consisting of C1-C6 alkyl, optionallythe C1-C6 alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12;

the terminal nitrogen is optionally further substituted with R3, whereinR3 is selected from the group consisting of hydrogen, oxygen, hydroxyl,and C1-C6 alkyl; and an optional counterion associated with the compoundwhich, if present, is selected from the group consisting of chloride,bromide, and iodide.

In particular, suitable surfactants or co-surfactants may include one ormore of any of Surfactants 1-6 described herein.

The surfactant system may be present in the insecticide formulation inan amount, measured in weight per volume, of about 1% or greater, about5% or greater, about 10% or greater, about 15% or greater, or about 20%or less, about 25% or less, about 30% or less, about 35% or less, about40% or less, or within any range using these endpoints.

The present disclosure further provides for compounds of Formula la:

wherein R1 and R2 may be the same or different, and comprise at leastone group selected from the group consisting of C1-C6 alkyl, optionallythe C1-C6 alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; m is an integer from 1to 6;the terminal nitrogen is optionally further substituted with R3,wherein R3 is selected from the group consisting of hydrogen, oxygen,and C1-C6 alkyl wherein the alkyl chain is optionally substituted withone or more substituents selected from the group consisting of carboxyl,carboxylate, and sulfonate; and an optional counterion may be associatedwith the compound and, if present, the counterion may be selected fromthe group consisting of chloride, bromide, and iodide.

The present disclosure additionally provides for compounds of FormulaIb:

wherein R1 and R2 may be the same or different, and comprise at leastone group selected from the group consisting of C1-C6 alkyl, optionallythe C1-C6 alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; p is 5; the terminalnitrogen is optionally further substituted with R3, wherein R3 isselected from the group consisting of hydrogen, oxygen, and C1-C6 alkyl,wherein the alkyl chain is optionally substituted with one or moresubstituents selected from the group consisting of carboxyl,carboxylate, and sulfonate; and an optional counterion may be associatedwith the compound and, if present, the counterion may be selected fromthe group consisting of chloride, bromide, and iodide.

One specific compound provided by the present disclosure is6-(dimethylamino)-N-(3-(1,1, 1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)hexanamide(Surfactant 1), having the following formula:

A second specific compound provided by the present disclosure is6-(dimethylamino)-N-(3-(1,1, 1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)hexaminiumchloride (Surfactant 2), having the following formula:

A third specific compound provided by the present disclosure is 36-((3-(1,1,1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)amino)-N,N, N-trimethyl-6-oxohexan-1-aminium iodide (Surfactant 3), having thefollowing formula:

A fourth specific compound provided by the present disclosure is6-((3-(1,1,1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)amino)-N,N-dimethyl-6-oxohexan-1-amineoxide (Surfactant 4), having the following formula:

In the structure above, the notation “N→O” is intended to convey anon-ionic bonding interaction between nitrogen and oxygen.

A fifth specific compound provided by the present disclosure is4-((6-((3-(1,1, 1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)amino)-6-oxohexyl)dimethylammonio)butane-1-sulfonate(Surfactant 5), having the following formula:

A sixth specific compound provided by the present disclosure is5-((6-((3-(1,1, 1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)amino)-6-oxohexyl)dimethylammonio)pentane-1-sulfonate(Surfactant 6), having the following formula:

These compounds may be synthesized by various methods. One such methodincludes reacting an amino acid, such as an N-alkylated or N-acylatedamino acid, with a siloxane to convert the amino acid C-terminus to thedesired siloxane derivative. The amino acid N-terminus may be furtherprotonated, alkylated, or oxidized to yield a quaternary amine or anN-oxide, for example.

The amino acid may be naturally occurring or synthetic or may be derivedfrom a ring opening reaction of a lactam, such as caprolactam. Thering-opening reaction may be either an acid or alkali catalyzedreaction, and an example of an acid catalyzed reaction is shown below inScheme 1.

The amino acid may have as few as 1 or as many as 12 carbons between theN- and C-terminii. The alkyl chain may be branched or straight. Thealkyl chain may be interrupted with nitrogen, oxygen, or sulfur. Thealkyl chain may be further substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carboxyl, and carboxylate. The N-terminal nitrogen may beacylated or alkylated with one or more alkyl groups. For example, theamino acid may be 6-(dimethylamino)hexanoic acid.

The siloxane may be substituted with one or more alkoxy groups, such asmethoxy, ethoxy, isopropoxy, tertiary butoxy, and others. The siloxanemay be further substituted with one or more alkyl groups, such aspropyl, wherein the alkyl group may yet be further substituted with anappropriate functional group to permit coupling of the siloxane to theamino acid, such as a nitrogen. For example, the siloxane may be3-aminopropyltris(trimethylsiloxy)silane.

The siloxane derivative of the amino acid may be synthesized as shownbelow in Scheme 2. As shown, 6-aminohexanoic acid is treated withformaldehyde in formic acid at reflux to give 6-(dimethylamino)hexanoicacid. The free carboxylic acid is then coupled to3-aminopropyl(trismethylsiloxy)silane in refluxing toluene to give thedesired siloxane derivative.

The N-terminal nitrogen may be further derivatized to modify or improvewater solubility and surface-active properties. A sample syntheticscheme is shown below in Scheme 3, in which the N-terminal nitrogen istreated with hydrochloric acid to give the corresponding hydrochloridesalt.

The N-terminal nitrogen may be alkylated. A sample synthetic scheme isshown below, in which the N-terminal nitrogen is treated with methyliodide to give the corresponding quaternary amine salt.

The N-terminal nitrogen may be treated with hydrogen peroxide in waterat reflux to give the corresponding N-oxide, as shown in the samplesynthetic scheme below, in Scheme 5.

The compounds of the present disclosure demonstrate surface-activeproperties. These properties may be measured and described by variousmethods. One method by which surfactants may be described is by themolecule’s critical micelle concentration (CMC). CMC may be defined asthe concentration of a surfactant at which micelles form, and abovewhich all additional surfactant is incorporated into micelles.

As surfactant concentration increases, surface tension decreases. Oncethe surface is completely overlaid with surfactant molecules, micellesbegin to form. This point represents the CMC, as well as the minimumsurface tension. Further addition of surfactant will not further affectthe surface tension. CMC may therefore be measured by observing thechange in surface tension as a function of surfactant concentration. Onesuch method for measuring this value is the Wilhemy plate method. AWilhelmy plate is usually a thin iridium-platinum plate attached to abalance by a wire and placed perpendicularly to the air-liquidinterface. The balance is used to measure the force exerted on the plateby wetting. This value is then used to calculate the surface tension (γ)according to Equation 1:

γ = F/I cosθ

wherein I is equal to the wetted perimeter (2 w + 2 d, in which w and dare the plate thickness and width, respectively) and cos θ, the contactangle between the liquid and the plate, is assumed to be 0 in theabsence of an extant literature value.

Another parameter used to assess the performance of surfactants isdynamic surface tension. The dynamic surface tension is the value of thesurface tension for a particular surface or interface age. In the caseof liquids with added surfactants, this can differ from the equilibriumvalue. Immediately after a surface is produced, the surface tension isequal to that of the pure liquid. As described above, surfactants reducesurface tension; therefore, the surface tension drops until anequilibrium value is reached. The time required for equilibrium to bereached depends on the diffusion rate and the adsorption rate of thesurfactant.

One method by which dynamic surface tension is measured relies upon abubble pressure tensiometer. This device measures the maximum internalpressure of a gas bubble that is formed in a liquid by means of acapillary. The measured value corresponds to the surface tension at acertain surface age, the time from the start of the bubble formation tothe occurrence of the pressure maximum. The dependence of surfacetension on surface age can be measured by varying the speed at whichbubbles are produced.

Surface-active compounds may also be assessed by their wetting abilityon solid substrates as measured by the contact angle. When a liquiddroplet comes in contact with a solid surface in a third medium, such asair, a three-phase line forms among the liquid, the gas and the solid.The angle between the surface tension unit vector, acting at thethree-phase line and tangent at the liquid droplet, and the surface isdescribed as the contact angle. The contact angle (also known as wettingangle) is a measure of the wettability of a solid by a liquid. In thecase of complete wetting, the liquid is completely spread over the solidand the contact angle is 0°. Wetting properties are typically measuredfor a given compound at the concentration of 1-100x CMC, however, it isnot a property that is concentration-dependent therefore measurements ofwetting properties can be measured at concentrations that are higher orlower.

In one method, an optical contact angle goniometer may be used tomeasure the contact angle. This device uses a digital camera andsoftware to extract the contact angle by analyzing the contour shape ofa sessile droplet of liquid on a surface.

Potential applications for the surface-active compounds of the presentdisclosure include formulations for use as shampoos, hair conditioners,detergents, spot-free rinsing solutions, floor and carpet cleaners,cleaning agents for graffiti removal, wetting agents for cropprotection, adjuvants for crop protection, and wetting agents foraerosol spray coatings.

It will be understood by one skilled in the art that small differencesbetween compounds may lead to substantially different surfactantproperties, such that different compounds may be used with differentsubstrates, in different applications.

The following non-limiting embodiments are provided to demonstrate thedifferent properties of the different surfactants. In Table 1 below,short names for the surfactants are correlated with their correspondingchemical structures.

Table 1 Surfactant Formula & Name Surfactant 1

Surfactant 2

Surfactant 3

Surfactant 4

Surfactant 5

Each of the five compounds are effective as surface-active agents,useful for wetting or foaming agents, dispersants, emulsifiers, anddetergents, among other applications.

Surfactants 1 and 2 candidates for use in a variety of surface cleaningand personal care product formulations as foaming or wetting agents.

Surfactant 3 is cationic. These surfactants are useful in both theapplications described above and some further special applications suchas surface treatments, such as in personal hair care products, and canalso be used to generate water repellant surfaces.

Surfactant 4 is non-ionic, and can be used in shampoos, detergents, hardsurface cleaners, and a variety of other surface cleaning formulations.

Surfactant 5 is zwitterionic. These surfactants are useful asco-surfactants in all of the applications described above.

The amount of the compounds disclosed herein used in a formulation maybe as low as about 0.001 wt. %, about 0.05 wt. %, about 0.1 wt. %, about0.5 wt. %, about 1 wt.%, about 2 wt.%, or about 5 wt.%, or as high asabout 8 wt.%, about 10 wt.%, about 15 wt.%, about 20 wt.%, or about 25wt.%, or within any range using any two of the foregoing values.

EXAMPLES

Nuclear magnetic resonance (NMR) spectroscopy was performed on a Bruker500 MHz spectrometer. The critical micelle concentration (CMC) wasdetermined by the Wilhelmy plate method at 23° C. with a tensiometer(DCAT 11, DataPhysics Instruments GmbH) equipped with a Pt-lr plate.Dynamic surface tension was determined with a bubble pressuretensiometer (Krüss BP100, Krüss GmbH), at 23° C. Contact angle wasdetermined with the optical contact angle goniometer (OCA 15 Pro,DataPhysics GmbH) equipped with a digital camera.

Example 1A

Synthesis of6-(dimethylamino)-N-(3-(1,1,1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)hexanamide(Surfactant 1) and6-((3-(1,1,1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)amino)-N, N-dimethyl-6-oxohexan-1-aminium salt (Surfactant 2)

6-(Dimethylamino)hexanoic acid (2.00 g, 12.56 mmol, 1 equiv.) wasdissolved in toluene (50 mL) in a 100 mL round bottom boiling flaskequipped with a Dean Stark trap, then3-aminopropyltris(trimethylsiloxy)silane (5.48 mL, 13.81 mmol, 1.1equiv.) was added. The reaction vessel was heated, and the reactionrefluxed for 24 hours until no more water separated in the Dean Starktube. The solvent was removed under vacuum to give Surfactant 1 as ayellow oil in 94% yield. ¹H NMR (500 MHz, DMSO) δ: 0.09 (s, 27H),0.28-0.31 (m, 2H), 1.12-1.26 (m, 2H), 1.27-1.30 (m, 4H), 1.38-1.41 (m,2H), 1.94 (t, J = 7.3 Hz, 2H), 2.00 (s, 6H), 2.06 - 2.03 (m, 2H), 2.89(dd, J = 12.9, 6.8 Hz, 2H).

In its neutral form, Surfactant 1 is slightly soluble in pure waterwithout addition of hydrotropes or other surfactants, but afterprotonation in slightly acidic conditions it becomes interfaciallyactive (Surfactant 2). The acidic conditions can be generated by theaddition of any acid or acidic buffer in the pH range of 4-7. Surfactant2 can also be prepared in non-aqueous solutions, for example by sparginggaseous HCl in toluene in the presence of Surfactant 1.

Example 1B Determination of Critical Micelle Concentration (CMC) ofSurfactant 2

The critical micelle concentration (CMC) for Surfactant 2 was testedwith a chloride counterion and was determined to be about 2 mmol. Theplateau value of minimum surface tension that can be reached by thissurfactant is about 23 mN/m. FIG. 1 is a plot of these results, showingsurface tension versus concentration.

Example 2A

Synthesis of6-((3-(1,1,1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)amino)-N,N,N-trimethyl-6-oxohexan-1-aminiumiodide (Surfactant 3)

Surfactant 1 (1.00 g, 2.02 mmol, 1 equiv.) was dissolved in acetonitrile(10 mL) in a 100 mL round bottom flask. Next, Na₂CO₃ (0.26 g, 2.42 mmol,1.2 equiv.) was added and the mixture was stirred for 10 minutes. Methyliodide (0.377 mL, 6.06 mmol, 3 equiv.) was added and the reaction washeated at 40° C. for 24 hours. The cooled reaction mixture was filtered,and the solvent was removed under vacuum to give Surfactant 3 as aslightly yellow solid in quantitative yield. H NMR (500 MHz, DMSO) δ0.09 (s, 27H), 0.38-0.42 (m, 2H), 1.23-1.26 (m, 2H), 1.37-1.40 (m, 2H),1.52-1.55 (m, 2H), 1.65-1.69 (m, 2H), 2.08 (t, J = 7.4 Hz, 2H), 2.99(dd, J = 13, 6.9 Hz, 2H), 3.04 (s, 9H), ), 3.24 - 3.33 (m, 2H).

The pure product is soluble in water and has surfactant properties. Thehalogen anions may be directly obtained from the N-alkylation reaction,and other desired counter anions may be obtained by anion exchange.

Example 2B Determination of Physical Properties of Surfactant 3

The critical micelle concentration (CMC) for Surfactant 3 was measured.From the surface tension change with concentration in water, the CMC wasdetermined to be about 1.6 mmol. The plateau value of minimum surfacetension that can be reached by this surfactant is around 20 mN/m,indicating that the surfactant has outstanding interfacial activity.These results are plotted as surface tension versus concentration inFIG. 2 .

The dynamic surface tension of Surfactant 3 was determined with a bubblepressure tensiometer which measures the change of surface tension of afreshly created air-water interface with time. FIG. 3 shows a plot ofthe results as surface tension versus time and demonstrates thatSurfactant 3 fully saturated the interface in less than 500 ms, makingit exceptionally fast in terms of interfacial adsorption.

In addition to Surfactant 3’s ability to lower both interfacial andsurface tension, formulations containing only Surfactant 3 haveexceptional wetting properties. For example, hydrophobic substrates suchas polyethylene and polypropylene exhibit a total surface wetting with acontact angle of 0°. On oleophobic and hydrophobic substrates such asTeflon, the measured contact angle was extremely low, 10.5° (Table 2).

Table 2 Substrate CA of Surfactant 3 (°) Concentration CA of water (°)Teflon 10.5 10x CMC 119 Polyethylene 0 10x CMC 91.5 Polypropylene 0 10xCMC 93.3 Nylon 0 10x CMC 50 Polyethylene terephthalate 0 10x CMC 65.3

EXAMPLE 3A

Synthesis of 6-((3-(1,1,1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3-yl)propyl)amino)-N,N-dimethyl-6-oxohexan-1-amineoxide (Surfactant 4)

Surfactant 1 (1.00 g, 2.02 mmol, 1 equiv.) was added to distilled water(80 mL) in a 100 mL round bottom flask, followed by 50% hydrogenperoxide (1.15 mL, 20.2 mmol, 10 equiv.). The reaction was refluxed for12 hours, then concentrated under vacuum. The residue was washed threetimes with acetone to give Surfactant 4 in 99% yield. ¹H NMR (500 MHz,DMSO) δ 0.09 (s, 27H), 0.38-0.44 (m, 2H), 1.21-1.25 (m, 2H),1.35-1.42(m, 2H), 1.50-1.55 (m, 2H), 1.71-1.75 (m, 2H), 2.05-2.08 (m,2H), 2.97-3.00 (m, 2H), 3.01 (s, 9H), 3.11 - 3.14 (m, 2H).

Example 3B Determination of Physical Properties of Surfactant 4

The critical micelle concentration (CMC) for Surfactant 4 was measured.From the surface tension change with concentration in water, the CMC wasdetermined to be about 0.49 mmol. The plateau value of minimum surfacetension that can be reached by this surfactant is about 20 mN/m,indicating that the surfactant has outstanding interfacial activity.These results are plotted as surface tension versus concentration inFIG. 4 .

The dynamic surface tension of Surfactant 4 was determined with a bubblepressure tensiometer. FIG. 5 shows a plot of the results as surfacetension versus time and demonstrates that Surfactant 4 fully saturated afreshly created air-water interface in one second or less, making itfast in terms of interfacial adsorption.

In addition to Surfactant 4’s ability to lower both the interfacial andsurface tension, formulations containing only Surfactant 4 inconcentrations of 1-100 x CMC have exceptional wetting properties. Forexample, a solution of Surfactant 4 in water at a concentration of 10xCMC exhibits a 0° contact angle on hydrophobic substrates such aspolyethylene and polypropylene, and 10.6° on oleophobic and hydrophobicsubstrates such as Teflon. These contact angles are extremely low incomparison with the contact angle of water on the same substrate (Table3).

Table 3 Substrate CA of Surfactant 4 (°) Concentration CA of water (°)Teflon 10.6 10x CMC 119 Polyethylene 0 10x CMC 91.5 Polypropylene 0 10xCMC 93.3 Nylon 0 10x CMC 50 Polyethylene terephthalate 0 10x CMC 65.3

Example 4A

Synthesis of4-((6-((3-(1,1,1,5,5,5-hexamethyl-3-((trimethylsilyl)oxy)trisiloxan-3₋yl)propyl)amino)-6-oxohexyl)dimethylammonio)butane-1 -sulfonate(Surfactant 5)

Surfactant 1 (1.00 g, 2.02 mmol, 1 equiv.) was added to ethyl acetate(EtOAc) (30 mL) in a 100 mL round bottom flask, followed by 1,2-butanesultone (0.27 mL, 2.2 mmol, 1.1 equiv.). The reaction was refluxed for12 hours, after which the solvent was removed and the resultant whitewaxy solid was washed with acetone to give Surfactant 5 in 50% yield. ¹HNMR (500 MHz, DMSO) δ 0.10 (s, 27H), 0.38-0.46 (m, 2H), 1.23-1.27 (m,2H), 1.37-1.68 (m, 10H), 1.73-1.78 (m, 2H), 2.45-2.48 (m, 2H), 2.97-3.01(m, 8H), 3.18-3.21 (m, 2H), 3.23-3.27 (m, 2H).

Example 4B Determination of Physical Properties of Surfactant 5

The critical micelle concentration (CMC) for Surfactant 5 was measured.From the surface tension change with concentration in water, the CMC wasdetermined to be about 0.39 mmol. The plateau value of minimum surfacetension that can be reached by this surfactant is about 21 mN/m,indicating that the surfactant has outstanding interfacial activity.These results are plotted as surface tension versus concentration inFIG. 6 .

The dynamic surface tension of Surfactant 5 was determined with a bubblepressure tensiometer. FIG. 7 shows a plot of the results as surfacetension versus time and demonstrates that Surfactant 5 fully saturated afreshly created air-water interface in one second or less, making itfast in terms of interfacial adsorption.

Finally, a solution of Surfactant 5 in water at a concentration of 10xCMC exhibits a 0° contact angle on hydrophobic substrates such aspolyethylene and polypropylene, and 10.2° on oleophobic and hydrophobicsubstrates such as Teflon. These contact angles are extremely low incomparison with the contact angle of water on the same substrate (Table4).

Table 4 Substrate CA of Surfactant 5 (°) Concentration CA of water (°)Teflon 10.2 10x CMC 119 Polyethylene 0 10x CMC 91.5 Polypropylene 0 10xCMC 93.3 Polyethylenterephthalate 0 10x CMC 65.3 Nylon 0 10x CMC 50Polyethylene-HD D 0 10x CMC 93.6

Example 5 Fracking Fluids

One of the compositions of the present invention comprises a mixture ofwater, a water soluble block co-polymer, and a non-ionic surfactant andinorganic salt containing mono- and/or di-valent and/or tri-valent ions.The preferred compositions of the present invention contain a mixture ofwater, a water soluble block co-polymer The relative amounts of theabove-named components in the composition can be varied. Typically, thecomposition has 0.05 to 20 wt. % water soluble block copolymer, 0.01 to10 wt. % nonionic surfactant, and 0.1 to 20 wt. % inorganic saltcontaining mono- and/or di-valent and/or tri-valent ions on a wet basis.The water-soluble mono- and/or di-valent electrolyte is typically usedin amounts of from about 1 weight percent to about 15 weight percent, orabout 1 to 10 weight percent, of the aqueous composition, based onweight of aqueous composition (a wet basis).

Some compositions of the present invention include a mixture of water, awater soluble block co-polymer The preferred compositions of the presentinvention include a mixture of water, a water soluble block co-polymerpolymer, inorganic salt and nonionic surfactants and are essentiallyfree of anionic surfactants.

The relative amounts of the above-named components in the compositioncan be varied. Typically, the composition has 0.05 to 20 wt % watersoluble block copolymer, 0.01 to 10 wit % nonionic surfactant, and 0.1to 20 wt % inorganic salt containing mono- and/or di-Valent and/ortrivalent ions on a wet basis. The water-soluble mono- and/or di-valentelectrolyte is typically used in amounts of from about 1 weight percentto about 15 weight percent, or about 1 to 10 weight percent, of theaqueous composition, based on weight of aqueous composition (a wetbasis).

The relative amounts of the above-named components in the compositioncan be varied. However, typical ranges for water soluble block copolymerand nonionic surfactant of the overall compositions of some embodimentsof the present invention on a wet basis are listed in TABLE 5.

Table 5 Water Soluble Block Polymer (wt. % wet basis) NonionicSurfactant (wt. % wet basis) Inorganic Salt Weight Percent (Broad)0.05-20 0.01-10 0.1 to 20 Weight Percent (Preferred) 0.1-10 0.08-3Weight Percent (More Preferred) 0.3-3 0.1-2 Polymer Weight 5000 g/mol-Average Molecular Weight (Broad) 1,000,000 g/mol Polymer Weight 10000g/mol- Average Molecular Weight (Preferred) 200,000 g/mol HLB (Broad)1-12 HLB (Preferred) 2-10 HLB (More Preferred) 6-10

The water-soluble inorganic salt containsmono- and/or di-Valent and/ortrivalentions. Inorganic salt concentration is typically used in amountsof from about 0.01 weight percent to about 20 weight percent or about 1weight percent to about 15 weight percent, based on weight of aqueousmedium, for example in amounts of from about 1 to 10 weight percent.

Example 6 Fracking Fluids

Nonlimiting examples of the inventive formulations include thecompositions listed Table 6.

Table 6 Ingredients 1 2 3 4 5 Hydrogen Chloride with AmmoniumBicarbonate 5.0 7.5 10.0 12.25 15.0 Sodium Alpha Olefin Sulfonate(surfactant) 2.0 2.0 2.0 2.0 2.0 PEG 6 2.0 2.0 2.0 2.0 2.0 Guar gumCarrier 0.0 balance 0.0 balance 0.0 balance 0.0 balance 1.0 balance

Example 7 Corn Oil Demulsification

The corn oil demulsification properties of Formulation Numbers 1 to 16in Table 8 below were investigated. Each formulation had corn oildemulsification properties.

Nonlimiting examples of the inventive formulations include thecompositions listed in Table 7.

Table 7 Ingredients 1 2 3 4 5 Hydrogen Chloride with AmmoniumBicarbonate 17.50 20.00 10.00 10.0 10.00 Sodium Alpha Olefin Sulfonate(surfactant) 2.0 2.0 3.0 4.0 5.0 PEG 6 4.0 4.0 3.0 4.0 1.0 GuargumCarrier 1.0 balance 1.0 balance 1.0 balance 1.0 balance 1.0 balance

Example 8 Fluids for Improved Oil Recovery

An exemplary composition of an injection fluid suitable for improvingthe recovery of oil or gas from a well is as follows: 10 (a) 0.01 to 5wt. % of one or more surfactants of the present invention, (b) anaqueous injection fluid, (c) 0-5 wt .% of one or more alkali, 15 (d) 0-1% of one or more viscosifiers, (e) 0-50 wt. % of one or moreco-solvents; (f) 0-50 wt. % of one or more co-surfactants, and; (g) 0-5wt % of one or more co-surfactants. The aqueous carrier includes but isnot restricted to water, produced brine, river water, synthetic brine,sea water.

Example 9 Formulations for Recovery Corn Oil from Stillage

Some exemplary corn oil extraction formulations are summarized in inTable 8. Corn oil demulsification Formulation Numbers 1 to 16 in Table8. Each formulation has corn oil demulsification properties.

The Polyglycerol Ester used was obtained from Lambent Technologies underthe product designation Lumulse POE (26) Glyc. It includes polymerizedglycerol and has an average of 26 moles of ethoxylation per mole ofpolymerized glycol. The Alkyl Polyglucoside used was BASF Glucopon® 225DK, an alkylpolyglucoside including a C8 -C10 alkyl group and an averageof 1.7 glucose units per mole of alkylpoly-glucoside.

Peg 400 used was polyethylene glycol having an average molecular weightof 400 daltons. Peg 400 MO used was polyethylene glycol monooleatehaving an average molecular weight of 400 daltons. Peg 400 DO used waspolyethylene glycol dioleate having an average molecular weight of 400daltons.

PEG 400 Mono Soyate used was an ester of polyethylene glycol (having anaverage molecular weight of 400 daltons) and fatty acids derived fromsoybean oil. Soybean oil is a triglyceride typically including fattyacids as follows: myristic 0.1%; palmitic 11.0%; palmitoleic.

Table 8 Formulation No. → 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 ComponentHLB White Mineral Oil 60 60 60 60 60 Polyoxyethylene Oleate (9 moles ofethoxylation) 12 20 10 Polyoxyethylene monostearate (40 moles ofethoxylation) 17.2 10 20 Hydrophobic Silica 10 10 10 10 10 10 10 10 1010 10 10 Castor Oil 13 10 18 20 30 54 60 100 90 10 Ethoxylate (40 molesof ethoxylation) Glycerol Ethoxylate (12 moles of ethoxylation) 17 20 60Glycerol Ethoxylate (26 moles of ethoxylation) 18.4 12 36 PEG 400 20 1030 Polyethylene glycol (average Mn 400) Polysorbate 80 15 90 80 35 45 10Propylene Glycol 3 10 55 37 Ester of Fatty Acids from Vegetable OilHydrophilic Silica 8 10 10 Water 10 80 80 All numbers are percetn byweight of the total composition

ASPECTS

Aspect 1 is a formulation for a fracking fluid, comprising:

at least one surfactant of Formula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; an optional counterion associated with thecompound which, if present, is selected from the group consisting ofchloride, bromide, and iodide;

Aspect 2 is the formulation for enhanced oil recovery, comprising:

at least one surfactant of Formula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; an optional counterion associated with thecompound which, if present, is selected from the group consisting ofchloride, bromide, and iodide; and

Aspect 3 is a formulation for a foaming emulsion, comprising:

at least one surfactant of Formula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; an optional counterion associated with thecompound which, if present, is selected from the group consisting ofchloride, bromide, and iodide; and a gas.

Aspect 4 is the formulation for recovery of bio based oil, comprising:

at least one surfactant of Formula I,

wherein R¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12;the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; an optional counterion associated with thecompound which, if present, is selected from the group consisting ofchloride, bromide, and iodide; and optionally a lecithin.

1. A formulation for the recovery of hydrocarbons, comprising: at leastone surfactant of Formula I,

wherein R ¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; an optional counterion associated with thecompound which, if present, is selected from the group consisting ofchloride, bromide, and iodide; and an aqueous phase.
 2. The formulationaccording to claim 1, further comprising at least one additionalsurfactant selected from the group consisting of: an anionic surfactanthaving a hydrophobic chain of 12 to 24 carbon atoms selected from thegroup consisting of sulfonate surfactants, sulfate surfactants, cationicsurfactants, nonionic surfactants, zwitterionic surfactants.
 3. Theformulation according to claim 1, wherein the aqueous phase includes atleast one inorganic salt, selected from the group consisting of: sodiumchloride, sodium sulfate, potassium chloride, magnesium sulfate, andmagnesium chloride.
 4. The formulation according to claim 1, furtherincluding at least one polymer.
 5. The formulation according to claim 4,wherein the at least one polymer is selected from the group consistingof: a quaternary ammonium compound, such as a cationic polymercomprising a quaternary diallyl dialkyl ammonium monomer, and/or ananionic surfactant, preferably an anionic polymer comprising an anionicmonomer selected from the group consisting of acrylic acid, methacrylicacid, and combinations thereof, wherein the average molecular weight ofsaid anionic polymer ranges from about 50,000 to about 10,000,000. 6.The formulation according to claim 1, further including lecithin ormodified lecithin.
 7. The formulation according to claim 1, furtherincluding at least one water immiscible solvent.
 8. The formulationaccording to claim 1, further including at least one water misciblesolvent.
 9. The formulation according to claim 1, further including atleast one gas selected from the group consisting of; air, nitrogen,carbon dioxide, and natural gas.
 10. The formulation according to claim1, further including at least one additive selected from the groupconsisting of: hydrogen chloride, an ammonium salt, ammoniumbicarbonate, ammonium carbonate, or ammonium hydroxide, alcohol,crosslinking agent, breaker delay agents, particles, proppants, gascomponent, breaker aids, oxygen scavengers, alcohols, scale inhibitors,corrosion inhibitors, fluid-loss additives, biocides/bactericides,friction reducers, and latex.
 11. A method of recovering a hydrocarboncomprising the steps of: introducing a foamed fluid composition withinan oil or gas well and performing an operation with the foamed fluidcomposition wherein the foamed composition comprises: a base fluidcomprises: an oil-based or a water-based fluid; a gas at least onesurfactant of Formula I,

wherein R ¹ and R² may be the same or different, and comprise at leastone group selected from the group consisting of C₁-C₆ alkyl, optionallythe C₁-C₆ alkyl may include one or more of oxygen, nitrogen, or sulfuratoms or groups that include at least one of these atoms, and the alkylchain may be optionally substituted with one or more substituentsselected from the group consisting of hydroxyl, amino, amido, sulfonyl,sulfonate, carbonyl, carboxyl, and carboxylate; n is an integer from 1to 12; the terminal nitrogen is optionally further substituted with R³,wherein R³ is selected from the group consisting of hydrogen, oxygen,hydroxyl, and C₁-C₆ alkyl; and an optional counterion associated withthe compound which, if present, is selected from the group consisting ofchloride, bromide, and iodide.
 12. The method of claim 11, wherein theoperation is selected from the group consisting of: a gas liftoperation, a drilling operation, a completion operation, a stimulationoperation, a fracturing operation, an injection operation, an enhancedoil recovery operation, and combinations thereof.